Can Colorado’s electric grid keep up as coal plants close and data centers open?

While campaigning for his first term in office, Gov. Jared Polis said he wanted to see 100% of the power on Colorado’s electric grid come from renewable energy sources by 2040. Lawmakers have approved bills furthering that vision by setting targets to cut greenhouse gas emissions, the goal being 100% reduction from 2005 levels by 2050.

Coal plants across Colorado have been shut down with all of them expected to close by the end of 2030. Rules by the city of Denver and the state are aimed at eventually making buildings all electric. Colorado has a goal of getting nearly 1 million electric vehicles on the roads by 2030 and recently moved ahead of California for the nation’s top spot in market share of electric vehicles sold in the state.

But does Colorado have the juice to keep up the pace on the road to a clean-energy future? Can the state shutter several power plants and still meet the everyday demands of keeping the lights, heat and air conditioning on — all while hitting targets for reducing emissions and expanding the use of renewables? How much will it cost?

The surging number of power-intensive mega computing centers and risks posed by more frequent and severe bouts of extreme weather are raising questions about how much the electric grid can take. And not just in Colorado.

A new study that the National Renewable Energy Laboratory in Golden participated in said the U.S. transmission system of a half million miles of power lines will need to at least double in size by 2050 to remain reliable at the lowest cost to ratepayers.

A 2024 report by the nonprofit North American Electric Corp. said about half the continent is at elevated or high risk of energy shortfalls over the next five to 10 years as power plants are retired and the pressure for more electricity escalates.

The nation’s demand for electricity, which has stayed more or less flat for two decades, suddenly jumped by roughly 3% in 2024, in large part because scorching heat during the summer caused many Americans to crank up their air conditioners, according to the New York Times.

Xcel Energy, Colorado’s largest electric utility, said in a proposal to replace the Comanche coal plant in Pueblo that projections show it will need from 12,500 to 14,000 megawatts of new power in the coming years. A forecast the company filed with the Colorado Public Utilities Commission said the demand for power could grow at a compounded rate of 4% from 2023 through 2031, compared with an average annual rate of 0.7% in the past five years.

“The plan is going to allow us and the state to meet our and the state’s ambitious emission reduction goals and also allow us to meet what we expect to be new demands from more building electrification, more transportation electrification and new data centers that are coming into the state,” Robert Kenney, president of Xcel Energy-Colorado, said when the proposal was released in October.

Minneapolis-based Xcel Energy plans to spend $45 billion on capital investments in the next five years with about $22 billion of that for Colorado.

Tri-State Generation and Transmission Association, Colorado’s second-largest electric utility, is a wholesale power provider that serves electric cooperatives in Colorado and three neighboring states. Lisa Tiffin, senior vice president of energy management, said the Westminster-based utility has been planning for several years to meet the growth in its normal electric load as well as increases driven by more electric vehicles, electrification of buildings and oil and gas operations and new data centers.

Working with its member cooperatives, Tri-State is adding renewable energy projects and ensuring the company has a reserve of power resources it listed on a state-required assessment. Tiffin said, “The reserve margin starts at 22% and increases to 30% by 2028” when its last coal unit in Craig will close.

“Houston, we’ve got a problem”

Overall, is Colorado on track to successfully shut down coal plants to decrease heat-trapping emissions, making the electric grid carbon-free and meeting the burgeoning demand for more power?

“If you’d asked me that question two years ago, I would have said, ‘Absolutely,’ ” said John Gavan, a former member of the PUC.

But Gavan worries about holdups on some renewable energy projects intended to replace coal units already scheduled to close. The closures could leave Colorado without enough “firm generation,” power that can be turned on and off as needed as opposed to wind and solar farms.

“It could lead to keeping coal plants online,” Gavan said. “What irks me is that nobody is standing up and saying, ‘Houston, we’ve got a problem.’ ”

Jack Ihle of Xcel Energy said the company “is not looking to extend the retirement dates of the coal plants.” The schedule has been established through a number of PUC orders, is part of state air quality regulations and has broad support in Colorado, said Ihle, the Colorado utility’s regional vice president of regulatory and strategy analysis.

Delayed renewable projects that were authorized about three years ago under an Xcel Energy clean energy plan are due in part to delays in approval of contracts for various reasons, said Mike Kruger, president and CEO of the trade group Colorado Solar and Storage Association. During that time, higher interest and inflation rates as well as supply-chain disruptions drove up prices, making it tough for companies to make good on their original bids on projects.

“If we were able to go from when the PUC gave approval, you would have seen more of these projects completed,” Kruger said. “But the longer we waited, the more the costs went up and the less able companies were to make the  bid price.”

In December, the PUC gave preliminary approval to increase the bid prices after requests from energy companies and Xcel. Kruger believes the state won’t meet its goals for expansion of renewables and decreased emissions by the end of the decade if the projects don’t go forward. The electric sector is required to cut greenhouse gas emissions by at least 80% by 2030.

“Not only are we closing the remaining coal plants in the state, but we’re seeing quite a bit of load growth, unlike anything we’ve seen in two decades,” Kruger said.

Grid Strategies, a consultant for the power sector, said in a December report that demand for electricity nationwide is forecast to rise by nearly 16% by 2029. Among the main drivers, according to the report, are data centers and manufacturing, spurred by the federal Inflation Reduction Act and CHIPS and Science Act. 

Northern Virginia is home to a quarter of the nation’s data-center capacity, but other states are becoming draws for the industry. Colorado has 56 of the facilities that house infrastructure for streaming, business computing, cloud storage and, increasingly, artificial intelligence. Xcel Energy has said it has “nearly 9,000 megawatts of opportunities” in the pipeline for powering data centers and about half the growth is likely to occur in Colorado in part because of its commitment to cleaner energy on the electric grid.

But renewable energy advocates worry that massive data centers could pose risks to achieving Colorado’s climate goals.

“In some states, utilities are building enormous new gas plants to serve data centers. To meet Colorado’s climate goals, we cannot have a massive buildout of new fossil fuels to serve data centers,” Garrett Royer, acting chapter director of the Colorado Sierra Club, said in an email.

‘Instead, we need data center operators to take the lead in procuring clean energy to serve their energy demands so the costs aren’t passed on to our communities,” Royer added.

Clare Valentine, senior policy adviser at Boulder-based Western Resource Advocates, said she’s “cautiously optimistic” that utilities, thanks in part to Colorado laws, will meet rising power demands first with renewable energy and not with new natural gas generation or keeping coal plants open longer than planned.

“Many data centers want to utilize clean energy to power their facilities. Utilities can and should work closely with them strategically to ensure renewable energy can meet that load growth,” Valentine said in an email.

And the state of Colorado should not provide incentives to attract data centers, Gavan said. He was a vocal critic of a failed bill in the 2024 legislative session that would have offered state sales and use tax rebates to centers that locate in Colorado. Opponents were concerned about the centers’ huge water and energy needs.

Polis and Will Toor, executive director of the Colorado Energy Office, said data centers can benefit ratepayers if the centers are carefully planned.

“There are a lot of relatively fixed costs on the system,” Toor said. “So if you add a new large load in a place where we already have the transmission that we need, you’re taking costs that everybody is paying for transmission and now spreading them over more kilowatt hours. It tends to exert a downward pressure on everybody’s rates.”

Scaling up transmission nationwide

When a study of the nation’s transmission system kicked off two years ago, the rising demand for electricity wasn’t the most important subject researchers were discussing.

“U.S. demand had been relatively flat. Now everybody is talking about it,” said David Palchak,, a senior researcher at the National Renewable Energy Laboratory.

The U.S. Department of Energy led the National Transmission Planning Study that was joined by NREL and Pacific Northwest National Laboratory. The study, released in December, identified a dramatic expansion of the country’s transmission system as the most cost-effective, reliable method of meeting the growing demand for electricity.

A big reason for the focus on transmission is the addition of more renewable energy to the grid. The energy sources are often far from populous areas, requiring more long-distance transmission lines.

“A simple example is when the wind is blowing really hard in the middle of the country and you have more than you need, you can ship it to another area,” Palchak said.

Expanding the transmission system would also help with increasing weather extremes: heat domes in the Pacific Northwest, winter storms in Texas. Areas going through withering heat or frigid temperatures can lean on their neighbors via grid connections, Palchak said.

The nation’s roughly half million miles of lines would need to be at least doubled by 2050, the study said. And researchers emphasize the need for interregional planning, coordination and construction.

Xcel Energy’s $1.7 billion Colorado Power Pathway will move power from renewable sources on the Eastern Plains to the Front Range via loops of roughly 550 miles of high high-voltage transmission lines. A segment that runs through Cheyenne, Kit Carson, Morgan and Washington counties is expected to be in service this year.

Palchak and other researchers say a national transmission expansion could be done at major cost savings, that every dollar invested would save $1.60 to $1.80. The study’s various scenarios show that accelerated transmission growth would save $270 billion to $490 billion nationwide through 2050.

“In the near term you get reductions in fuel costs” with wind, solar and battery storage, Palchak said.

In the long term, money would be saved because fewer new power plants would have to be built. Palchak said several different parties, including industry experts and state governments, gave feedback during the study.

“The hope is that people are going to be able to pick this up and be able to use it, maybe influencing the decisions they are going to be making,” Palchak said.

“It’s possible this time’s different”

“I think it’s important to always remember that forecasts are not reality and we’ve seen forecasts before that have been wildly overstated in terms of the forecasted load growth versus what actually showed up,” said Mark Dyson, a managing director at RMI, a nonpartisan think tank focused on a zero-carbon energy future.

“That said, it’s possible this time’s different,” he added. “Contracts are being signed today for facilities that will add hundreds of megawatts, even gigawatts of power once they’re constructed.”

Dyson said the growth in the electricity load was relatively flat for the past 15 or 20 years. Now, the move to electric vehicles, more electric heating and cooling, increased manufacturing and the spread of data centers are boosting demand. He sees a strong case for expanding transmission systems to help meet the growing load and for more connections across regions.

“We also need to be smart about how we use the grid in general,” Dyson said.

That’s where grid-enhancing technologies come in. The equipment and practices enable systems to get more power from their electrons, sometimes avoiding the need for expensive new infrastructure. The technologies include:

• Reconductoring, or replacing conventional transmission lines with advanced conductors without having to permit and build new transmission towers.
• Clean repowering, or siting clean energy alongside existing fossil generators to leverage their grid connections.
• Dynamic line ratings, which adjust the carrying capacity of transmission lines based on real-time measurement of conditions.
• Virtual power plants, or aggregated distributed energy resources such as batteries, electric vehicles, rooftop solar and smart thermostats that can feed into the grid.

The use of grid-enhancing methods is more common in other countries, Dyson said. In the U.S., utilities are compensated for capital expenditures, lessening the incentive to use grid-enhancing technologies, RMI said.

Rebecca White, PUC director, said the state wants to see those types of technology used because they save money for ratepayers. She noted that a report by the Colorado Electric Transmission Authority found that upgrading transmission lines is a cost-effective way to increase capacity in existing transmission corridors.

“Nationwide we see at least a 60 gigawatt potential by the end of this decade from aggregating the flexibility inherent in these resources that are already out in the world and have already been bought and paid for,” Dyson said.

“We take reliability very seriously”

Once criticized as being too reliant on coal, Tri-State has been closing coal facilities and will shut more by 2031. The utility retired its share in plants in New Mexico, closed its plant in Nucla in 2019 and retired its share in a plant in Craig in 2025.

Tri-State plans to retire its last unit at coal plant in Craig in early 2028, about two years earlier than previously scheduled. A coal unit in Springerville, Ariz., will be retired in 2031. Tri-State is preparing requests for proposals for more renewable energy sources in addition to dispatchable sources that can be turned on and off as needed, such as natural gas.

In 2023, according to the latest available figures, Tri-State got 40% of its electricity from coal; 33% from renewables; 17% from the marketplace; and 10% from natural gas and oil.

Tri-State expects renewables to make up 70% of the energy on its system by 2030 and anticipates cutting its greenhouse gas emissions 80% from 2005 levels by then.

Tiffin said Tri-State goes through a robust modeling process to determine the volume and kind of energy it needs for peak demand. A 100-megawatt wind facility might generate only 14 megawatts of power in certain instances, she said.

“What can we truly count on? That’s how we stack up that capacity against our reserve margins,” Tiffin said.

The utility serves a total of 41 member associations in Colorado, Wyoming, Nebraska and New Mexico. Tri-State has about 1 million electric customers over 200,000 square miles. It has various partnerships across the region that allow it to buy power from providers when it needs to.

“We want to leverage interconnections where we can,” Tiffin said. “One of the benefits of being in a cooperative system is we are very much trying to expand the ability, flexibility of our members to bring on resources, which includes some programs at utility scale.

“The more of that we have, the more we avoid those big transmission bills,” she said.